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January 18, 2026

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Wash. AG, Environmental Groups Challenge DOE’s Centralia Coal Plant Order

Washington’s attorney general and a coalition of environmental groups have mounted separate challenges to the U.S. Department of Energy’s December decision to order TransAlta to continue operating the state’s last coal-fired plant for three months beyond its scheduled retirement at the end of 2025.

Attorney General Nick Brown and the coalition — which includes Earthjustice, NW Energy Coalition, Washington Conservation Action, Climate Solutions, Sierra Club and the Environmental Defense Fund — have separately filed requests to rehear DOE’s Dec. 16, 2025, order to keep the Centralia Power Plant’s 670-MW Unit 2 running until March 16, 2026, due to an energy “emergency” in the Pacific Northwest this winter. (See DOE Orders Retiring Wash. Coal Plant to Stay Online for Winter.)

The order was one in a series of such moves the Trump administration’s DOE has taken over the past year to extend the life of aging fossil fuel-fired plants slated for closure, including in Michigan, Pennsylvania and Colorado.

“The Trump administration is once again ignoring both the law and the facts,” Gov. Bob Ferguson said in a Jan. 13 statement accompanying announcement of the state’s request, which asks DOE to “immediately withdraw” the order. “DOE needs to reverse course on this harmful and misinformed order.”

“DOE is misusing its narrow authority reserved for imminent emergencies to force a dirty, inefficient coal plant to keep operating,” Earthjustice attorney Patti Goldman said in a Jan. 14 statement by the coalition. “Our region has moved beyond reliance on coal and this plant. We are meeting our region’s energy needs, now and into the future, with cleaner sources.”

In their statements, the AG’s office and the coalition questioned DOE’s authority to keep the Centralia plant open under Section 202(c) of the Federal Power Act — and the department’s reason for doing so, arguing that the law is intended to address only “real” emergencies.

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The coalition contended that the order “exceeds that authority and instead tries to impose the administration’s preference for coal-fired power over a 2011 agreement between the state of Washington and TransAlta, the owner of the plant, to shut down the plant by the end of this year.” (Unit 1 at Centralia was shut down in 2020 under the first phase of that agreement, and TransAlta plans to convert the facility to natural gas.)

The AG said the order “is a clear attempt by DOE to bypass the limits imposed on it by Congress.”

In its rehearing request, the AG said the department failed “to properly identify or clarify the appropriate entities that have any authority to direct” Centralia’s operation. The Dec. 16 order called on TransAlta to “take all measures necessary” to ensure the plant is available operated at the direction of either the Bonneville Power Administration as a balancing authority or CAISO’s RC West as the regions reliability coordinator, but it was apparent neither of those entities was consulted before the order was issued.

Getting the Story Straight

The coalition in its rehearing request argued that DOE failed to provide evidence of an energy emergency or electricity shortage that warranted continued operation of the plant. It notes that two third-party studies cited by DOE to support its order “demonstrate the absence of an emergency.”

The coalition points out that the first study, NERC’s assessment of reliability for this winter, “expressly states that ‘operating reserve margins are expected to be met after imports in all winter scenarios.’ … This means that the study on which the department relies anticipates that the region will be able to meet peak demand and maintain the full added buffer of reserves on top.”

The second study, by Energy and Environmental Economics (E3), has not yet been released, the coalition noted. Instead, DOE based its finding on a September 2025 presentation on the pending study, whose author has said shows the Northwest’s resource adequacy risk is “slightly elevated above the target risk,” which “was calculated to achieve a loss of load expectation of one event-day per decade.”

“E3 also confirms that it calculated this ‘slightly elevated’ risk without examining the actual conditions this winter; as a planning document, the presentation is based on a historical model and does not reflect actual weather and hydrological conditions presently existing for this winter,” the coalition wrote in the rehearing request.

The coalition contends that recent actions by DOE undercut the department’s claim of an emergency, including an October 2025 order by the Grid Deployment Office that allowed the Northwest to export electricity to Canada based on a finding (in DOE’s own words) “that the wholesale energy markets are sufficiently robust to make supplies available to exporters and other market participants serving United States regions along the Canadian and Mexican borders.”

In that order, DOE itself pointed to the “comprehensive” reliability processes in the region that ensure “bulk-power system owners, operators and users have a strong incentive both to maintain system resources and to prevent reliability problems that could result from movement of electric supplies through export,” the coalition noted.

“The Trump administration can’t get its story straight,” Tyson Slocum, Public Citizen’s Energy Program director, said in the coalition’s statement. “While it claims the West Coast is in a state of emergency requiring families to bail out an expensive coal plant, Trump’s Department of Energy is simultaneously concluding the region has energy abundance to authorize electricity exports to Canada. Which is it, Donald?”

The coalition contends that complying with the DOE order will “be expensive, as Centralia does not have the coal, customers or workforce to keep the coal plant running. Other coal plants forced to keep operating are experiencing extremely high costs, which [FERC] can require ratepayers to pay.”

The groups point to the pollution impact of the order, and how it violates Washington’s Clean Energy Transformation Act, which required the state’s utilities to stop using electricity from coal-fired plants by the end of 2025.

“So many of us — from state leaders and utilities to elected officials and public interest groups — have worked for decades to plan for and build cleaner, more efficient generation and transmission that will ensure Washington state’s transition to clean energy while keeping energy affordable and reliable,” said Lauren McCloy of the NW Energy Coalition. “That work is ongoing, and burning more coal at Centralia is not the answer to meeting growing energy demand in the Northwest.”

Asked to comment on the challenge, a DOE spokesperson responded: “Under the disastrous energy subtraction policies of the previous administration, the U.S. was on track to lose 100 GW of reliable generation capacity by 2030. Much of the U.S. is now at ‘elevated risk’ of blackouts under extreme conditions, which NERC declared a ‘five-alarm fire’ for grid reliability.

“At the same time, the U.S. may need to build 100 GW of new reliable capacity to win the AI race and onshore manufacturing. The Trump administration is committed to preventing the premature retirement of baseload power plants and building as much reliable, dispatchable generation as possible to achieve energy dominance.”

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Resetting the Reset: Demand Curve Reform Discussions Begin

NYISO kicked off the demand curve reset reform process with a discussion of how to improve the overall process and what could be done to strengthen the definition of the proxy unit. The ISO seeks to stabilize the installed capacity market by reducing volatility and making the DCR less complex and burdensome.

“I think, uncontroversially, we can consider this process quite burdensome for both NYISO and stakeholders, and we want to address those issues now as part of a project,” said Michael Ferrari, a market design specialist for NYISO.

No specifics, tariff changes, definitions or formulas were discussed. The discussion at the Jan. 12 Installed Capacity Working Group Meeting was centered on possible avenues to improve the DCR and what the ISO might explore with stakeholders.

The DCR anchors capacity prices on a curve by picking a “proxy unit” to represent the cost of a hypothetical new generator entering the market every four years. The most recent DCR set a two-hour battery energy storage system as the proxy unit for the 2025/29 period. (See FERC Accepts NYISO Demand Curve Reset.)

The current process involves considerable debate, outside consultation and stakeholder meeting time to pick a type of generator to serve as the proxy unit and determine a reasonable hypothetical capital cost estimate for it. Debating the engineering cost assessments to estimate capital costs for potential technology takes much of the 18-month DCR process. These findings are subject to an annual adjustment to try to keep the curve in line with market conditions.

“We want to address the issues now as part of a project before the status quo process of the demand curve reset begins in earnest,” said Ferrari.

Ferrari outlined some of ISO’s preliminary ideas for smoothing the DCR. The ISO is considering a periodic review that would use the existing annual update framework to apply systemic, formulaic adjustments to reduce the need for a total reset every four years. This would involve using cost-trend publications, inflation-based indexes and various annual financial parameters such as interest rates to adjust prices periodically. This would, in theory, reduce the administrative burden by getting away from detailed engineering studies.

NYISO also is considering redefining the proxy unit. It would no longer be a unit based on specific technology; instead, the proxy unit would merely be a hypothetical unit that meets a minimum operating criterium.

Stakeholders seemed skeptical of NYISO’s proposal. Some pointed out that national price indexes were extremely bad at predicting costs in New York City. Others pointed out that the annual adjustment mechanism already doesn’t work very well.

“I think it’s fair to say, not pejoratively, that the analysis group kind of threw up their hands and said ‘Well, there really aren’t good indices for certain things so this is as good as it can get,’” said Doreen Saia, a lawyer for Greenberg Traurig, referring to the NYISO consultant’s comments during the last DCR. (See NYISO Offers Final Staff Recommendations for Demand Curve Reset and NYISO Stakeholders Continue Debate over Battery as Proxy Unit.)

Adam Evans, a representative of the New York Department of Public Service, pointed out that the status quo was not tenable.

“In the last reset we saw a potential $2.5 billion increase in demand curve cost based on what some folks were arguing for the proxy unit, which is frankly untenable,” said Evans. “I think this type of proposed solution to limit volatility … I think it makes sense.”

Other stakeholders pointed out that the current DCR process was not responsive or flexible in the face of state policy shifts. One stakeholder pointed out that state incentives for procuring carbon-free energy were not incorporated into the cost of new entry models. Another said the state climate law could be altered or removed by the legislature if the political winds shifted and any new process would have to account for that.

“I would be very concerned about trying to have a demand curve process that is super responsive to every policy shift that comes at us. That undermines the idea of certainty,” said Mike DeSocio, a consultant with Luminary Energy. He disagreed with the idea of a flexible process and asked NYISO to instead focus on market certainty.

Stu Caplan, representing New York Transmission Owners, said the market should not be designed for high price increases without reliability gains.

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Judge Allows Construction to Resume on Empire Wind

Equinor has won a temporary injunction against the Trump administration’s stop-work order on U.S. offshore wind projects, allowing it to resume work on Empire Wind.

The Department of the Interior on Dec. 22 shut down work on all five projects under construction in U.S. waters, citing national security concerns.

Empire, which incurred millions of dollars in added costs from a monthlong stop-work order in April and May 2025, filed a challenge to the new stop-work order Jan. 2 and a motion for preliminary injunction Jan. 6 in U.S. District Court for the District of Columbia (1:26-cv-00004).

After a Jan. 14 hearing, District Judge Carl Nichols — appointed to the federal bench by President Donald Trump in 2019 — granted the motion Jan. 15.

Equinor, which holds an offtake contract with New York for the 810-MW Empire Wind project, had told the court it likely would need to abandon the project if it could not resume work by Jan. 16. With any further delay, it said, crews would not be able to finish a key component before the specialized installation vessels had to depart for the next contracted work.

Later Jan. 15, Equinor said: “Empire Wind will now focus on safely restarting construction activities that were halted during the suspension period. In addition, the project will continue to engage with the U.S. government to ensure the safe, secure and responsible execution of its operations.”

It was the second court victory this week for the beleaguered U.S. offshore wind sector.

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On Jan. 12, another Republican-appointed federal judge lifted the stop-work order on Revolution Wind, a 704-MW project nearing completion off the New England coast. (See Judge Again Lifts Revolution Wind Stop-work Order.) The same judge also lifted the Trump administration’s August stop-work order against Revolution.

Meanwhile, Dominion Energy is contesting the stop-work order on Coastal Virginia Offshore Wind, a 2.6-GW wind farm near completion, and Ørsted is fighting to restart work on the 924-MW Sunrise Wind, an earlier-stage New York project. (See Offshore Wind Developers Fight to get Back in the Water.)

Vineyard Wind was the last project to join the legal fray. On Jan. 15, it filed a complaint in U.S. District Court in Massachusetts (1:26-cv-10156) asking the court to declare the stop work order unlawful and allow work to resume.

The Avangrid-Copenhagen Infrastructure Partners joint venture is 95% complete and already able to send 572 MW of its planned 800-MW capacity to the New England grid, according to the court filing. Construction began in 2021 and was on track to be completed by March 31.

In a statement, the developers said they will continue to work with federal regulators to understand the matters raised in the stop-work order but believe the order was unlawful and said if it is not promptly enjoined, it will cause immediate and irreparable harm to the project and the communities that will benefit from it.

Despite the setbacks it has sustained in court, the Trump administration has succeeded to a significant degree in its bid to thwart offshore wind development: The level of risk it has created has scared away further investment.

The five offshore wind projects hit with the Dec. 22 stop-work order constitute the entire large-scale U.S. offshore wind sector, and they appear unlikely to be followed by others anytime soon. To cite the obvious example, Empire Wind 2 has been shelved indefinitely.

Oceantic Network welcomed the Jan. 15 ruling: “Empire Wind is critical to securing New York’s electric grid, stabilizing rising energy costs for local communities, creating jobs and achieving energy independence, underscoring the importance of building out America’s energy infrastructure to meet rising electricity demand.”

Regional Plan Association hailed the win but warned it is not a final victory: “Despite the good news of these decisions, they still do not ensure that these projects will be completed. The court rulings are temporary injunctions that allow the companies to continue to build while the lawsuits against the administration’s efforts to stop them make their way through the courts. Even an ultimate victory against the administration’s freeze — based on supposed national security concerns — does not prevent them from taking additional steps to disrupt, delay or cease the projects.”

Advanced Energy United said: “Restarting Empire Wind is a major win. This project will deliver clean power and local jobs exactly when we need them the most. Today’s ruling shows that smart energy planning beats political games every time — and that delaying critical projects only drives up costs for consumers.”

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Pessimistic PJM Slightly Decreases Load Forecast

PJM‘s 2026 load forecast has decreased the amount of growth expected for the following six years owing to a more pessimistic view of the volume of large loads, economic growth and electric vehicles.

The forecast continues to expect that load growth will accelerate over the 20-year scope, with load reaching 253 GW in 2046.

Load growth still is expected in the near term, just slower — particularly in the winter. For the summer of 2028, the total load expected is 2.6%, or 4.4 GW, lower than the 2025 forecast; for the following winter, the estimates are 3.8%, or 5.8 GW lower. Between 2027 and 2031, the summer peak is expected to grow to 191 GW, up 30 GW. By 2046, the peak is expected to reach 253 GW for the summer and 237 GW in the winter.

PJM said the forecast was likely to cut into the 6.6-GW shortfall in the 2028/29 Base Residual Auction (BRA). While the haircut is not enough to make up the difference, the RTO said it also expects some resources scheduled to deactivate and winter-only resources without an annual commitment to be available. (See PJM Capacity Auction Clears at Max Price, Falls Short of Reliability Requirement.)

Data center load growth has been the primary cause of the growing capacity shortfall and billions of dollars in transmission projects. The Board of Managers is considering a slate of proposals to rework the capacity market to address large loads, as well as an $11 billion Regional Transmission Expansion Plan to increase transfer capability into growing load clusters in Virginia, Pennsylvania and Ohio.

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EnergyHub and Brattle Study Finds Big Savings from Managed EV Charging

EnergyHub and Brattle Group released a report showing that utilities can achieve significant savings if they actively manage electric vehicle charging.

“Demonstrating the Full Value of Managed Electric Vehicle Charging” includes the results of a real trial of 58 EV drivers in Washington state who got $100 upfront and $10 per month when they limited opt-outs to three or fewer in a month. They were tested for four weeks with time-of-use rates. Energy Hub actively managed their charging using an unmanaged baseline on flat, volumetric rates.

“We found that with the solution, it enabled distribution utilities to host over twice the number of EVs on the same system as if they were unmanaged,” Energy Hub CEO Seth Thompson said in an interview. “So, it kind of doubles the distribution grid’s EV hosting capacity just by managing the EV charging load and in terms of cost impacts. We found that in the long term, it could bring the cost of hosting EVs from about $800 per year per EV if they were unmanaged, to about half of that if they were managed.”

EnergyHub’s main business is to contract with utilities to manage EVs and distributed energy resources (DERs) on their systems.

In the past, a lot of that work was focused on replicating a peaker plant with distributed resources. But as EVs become more common, the industry needs a way to manage their impact on distribution circuits.

“EVs clearly were starting to apply a degree of pressure to the distribution grid where the sort of traditional idea of a one-time or occasional, discrete activation of a VPP [virtual power plant] was not what the grid needed,” Thompson said. “The grid needed a system that sits there running all the time, protecting the system from overloads and essentially just moving load around to raise your utilization factor. That’s the future of VPPs, to be able to do both of those things.”

Active managing of EV charging delivers 95% of that load to off-peak hours, which helps cut customer bills. A more passive approach using time-of-use (TOU) rates (with lower off-peak charges) can deliver similar benefits when EV penetration is low, but it can exacerbate peaks when too many EVs are on one distribution circuit, Brattle managing associate and report co-author Akhilesh Ramakrishnan said in an interview.

“It’s not a generalized finding about TOU, but it’s specific to the type of load that EVs are, where they’re basically this kind of huge load that’s coming from one source,” he added “EVs can be double the peak load of a typical house, and so you really don’t want all of these things charging and discharging at the same time.”

A chart from the report showing the costs in system upgrades per EV by different charge management styles. | Brattle

With passive TOU rates, customers would set their EVs to start charging once the cheaper power kicks in and everyone on the block would start pulling power at the same time, leading to a larger peak than even flat rates. Energy Hub’s management system can spread those charges over the entirety of the off-peak hours, flattening the peak.

“Every EV will let you set a charging schedule, and essentially, if you were trying to do this through behavior change, the more successful you are at getting everybody to pay attention to that black-and-white pricing signal, the greater the peak,” Thompson said. “And so, the ideal combination is a mix of the TOU signal and a piece of software that kind of randomizes and distributes that strategically over time.”

The study looked only at TOU rates, which offer discounts in off-peak hours. Thompson argued that more complex rates, like passing through wholesale costs, do not attract customers.

“If you go around Europe, if you go to Australia, in major other markets, the per capita participation with flexible loads is lower than it is in the U.S.,” Thompson said.

EnergyHub’s and other distributed energy resource management systems (DERMS) can link up EVs, solar panels, smart thermostats and other resources to those wholesale signals and optimize their performance for the grid, Thompson said.

The need for that management scales up with EVs on the system. Ramakrishnan said a local grid can handle a car or two but that once more start to plug-in, their charges need to be managed to avoid the need for distribution upgrades.

“You can assume there’s a random distribution of these things up to a point, and you never know whether you’re already basically at capacity or there’s tons of headroom,” Thompson said. “The other thing that you hear from utilities all the time is that there’s clustering, and so you might have 5 or 10% adoption in the service territory, but you might have 25% in a neighborhood.”

The market changed for EVs in general in 2025 as federal tax incentives expired at the end of the third quarter. That led to a spike in purchases as consumers sought to take advantage of those, Thompson said.

Now the industry is waiting for new quarterly figures to get a sense of how fast EV sales will grow absent federal tax incentives. Even with those incentives, most of the plug-in models were more expensive, which kept their sales numbers low. With technology improving, prices are expected to come down and that could lead to significant growth.

“We now have the ability to tackle this in an orderly way,” Thompson said. “What’s nice about the way we’ve built this solution is that a utility can adopt it very cost effectively at small scale, get comfortable with sort of understanding what does it do? How does it work? How do they integrate it with our other systems?”

Once they begin building consumer awareness, “as they hit these levels of kind of a critical mass, whether that’s locationally or across their whole system, they’re ready for it,” he added.

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CISA, Peers Provide OT Connectivity Principles

To help critical infrastructure organizations strengthen their cybersecurity stances, the Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency and several foreign counterparts have provided a set of principles to guide internet connectivity for operational technology environments.

The Secure connectivity principles for operational technology (OT) document was published Jan. 14 with contributions from CISA, the FBI, the Australian Signals Directorate, Germany’s Federal Office for Information Security, the Canadian Centre for Cyber Security and Communications Security Establishment, and the National Cyber Security Centres of the U.K. and New Zealand. The U.K. NCSC hosted the document on its website.

OT assets — which interact with the physical environment or manage devices that do so, according to the National Institute of Standards and Technology — have traditionally been separated from internet-connected systems for security reasons, but in today’s industrial landscape are increasingly integrated with information technology networks to increase business efficiencies.

Such integration can create security risks for reasons including “dependence on legacy technologies that were never designed for modern connectivity or security requirements,” along with the use of third-party tools, remote access and supply chain integrations that “expand the potential attack surface,” the agencies wrote. The risks of cyber intrusion are “elevated” in an OT environment because the consequences can include disruption of essential services, environmental impact and physical harm to employees and customers.

Experts have warned that OT networks are increasingly vulnerable to attack. Cybersecurity firm Dragos identified multiple new adversary groups in its annual Year in Review report, at least one of which demonstrated the capability to meaningfully attack industrial control systems. (See Dragos: Attacks on ICS Increased in 2024.)

In a later case study, the firm reported that the China-connected hacking group Voltzite had infiltrated a U.S. electric utility’s computer system in 2023. (See Dragos Outlines Voltzite Electric Utility Breach.)

8 Principles

The new document organizes its guidance into eight principles, to be used “as a framework to design, implement and manage secure OT connectivity.” Agencies encourage device manufacturers and integrators to make the principles easy to achieve through equipment design and documentation.

The first principle is balancing risks and opportunities when identifying where and how connectivity is permitted within OT systems. Entities should develop a business case that supports decision-making and documents the purpose of the connectivity, potential impacts of a compromise to the connectivity, senior risk owners and any dependencies that may be introduced by the connection. Organizations must also exercise control and oversight of their supply chains; agencies recommended previous publications to help with this, including CISA’s Secure by Demand guidance.

Principle 2 is limiting the exposure of the connectivity; exposure means “where an asset sits within the wider system architecture and how accessible it is to external or adjacent networks,” according to the document. An organization’s attack surface broadens as more assets are exposed at the network edge. An effective exposure management approach involves evaluating an asset’s placement in the network, the type of connectivity it involves and the strength of cybersecurity controls.

Mitigation measures can include reducing the time of exposure and removing inbound port exposure so that connections to the OT environment can only be initiated from within the network. Entities must also manage the risks posed by obsolete technology, by replacing the relevant devices when possible and shoring up defenses around equipment that cannot be replaced yet.

The third principle is centralizing and standardizing network connections, which can be difficult to manage as the presence of third-party equipment on the system grows. This is also a factor in principle 4, which calls on entities to use standardized, secure protocols for communication so that data flows can be readily monitored for trouble signs.

Hardening the OT boundary is principle 5, with network segmentation and segregation providing “a robust first layer of defense [and being] even more effective when combined with native security capabilities within OT systems.”

“Because many OT systems are difficult to update or replace, the boundary becomes the primary defense against external threats,” the agencies wrote. “Organizations should therefore invest in modern, modular and easily replaceable boundary assets. … These assets offer greater flexibility for patching, upgrading and reconfiguring security controls. Importantly, they can be maintained without disrupting core OT operations.”

Principle 6 involves limiting the impact of compromise with “controls that extend beyond the OT boundary.” With effective controls such as network segmentation, organizations can limit the effects of contamination and inhibit intruders’ ability to move laterally within a system, a capability demonstrated recently by the China-linked Volt Typhoon group.

The next principle calls for logging and monitoring all connectivity, which the document called an organization’s “last line of defense.” Monitoring connectivity helps defenders identify abnormal activity that can indicate compromise.

Finally, organizations should create a plan to isolate their OT environments completely from external influences, which comprises principle 8. Strategies can vary based on the nature of the network. Site isolation, which involves removing all external network connections, is applicable for sites built on a flat network or with restricted security measures, while more robust security architectures may allow for specific services and network routes to be isolated with others left unaffected.

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ISO-NE Details Inputs for Capacity Auction Reform Impact Analysis

ISO-NE outlined its methodology for analyzing potential effects of its capacity auction reform (CAR) project at the NEPOOL Markets Committee meeting Jan. 14, detailing resource mix and load inputs for the near- and longer-term base cases and potential factors to be considered in sensitivity analyses.

The RTO plans to present the initial results of the impact analysis starting in March and will work with stakeholders to develop sensitivities building on the two base cases.

“This analysis will provide stakeholders with a better understanding of how CAR may impact how much capacity they can sell, and wholesale market revenues and costs under specific scenarios, as well as other key parameters,” said Chris Geissler, director of economic analysis at ISO-NE.

The near-term base case “seeks to use assumptions that are broadly in line with expected system conditions for CCP [capacity commitment period] 19,” said Fei Zeng, manager of planning services at ISO-NE.

CCP 19 will procure capacity for the 2028/29 commitment period; ISO-NE aims to implement both phases of the CAR project for this period. The first phase of CAR, filed with FERC at the end of 2025, centers around implementing a prompt capacity auction and resource deactivation reforms. The second phase centers around resource capacity accreditation and the development of seasonal capacity commitment periods. (See NEPOOL Supports First Phase of ISO-NE Capacity Market Reform.)

The RTO plans to rely on resource mix modeling assumptions from the most recent annual reconfiguration auction, adjusting the mix based on planned deactivations, under-development resources that have withdrawn from critical path schedule monitoring and resources that qualified in the 2025 interim qualification process. The resource mix assumptions result in about 37,500 MW of non-intermittent qualified capacity and about 2,000 MW of intermittent qualified capacity.

To estimate demand, ISO-NE will use the 2028/29 load forecast from its 2025 capacity, energy, loads and transmission (CELT) report.

For the longer-term modeling base case, ISO-NE plans to use the 2025 CELT demand forecast for 2035. The RTO plans to approximate the resource mix for 2035 by adding 2,000 MW of offshore wind, 200 MW of utility solar and 200 MW of two-hour batteries. These resource additions “may be aligned with a conservative approximation on progress toward the states’ public policy by this time frame” and are meant to serve as a “starting point to build from,” Geissler said.

Some stakeholders expressed concern that the longer-term base case includes too little storage at too short of a duration. In response, ISO-NE emphasized that conservative assumptions should help provide a good point of comparison for subsequent sensitivity analyses evaluating increased levels of storage and renewable penetration.

For both base cases, the impact analysis will provide information on estimated effects on the net installed capacity requirement, marginal reliability impact demand curves, and seasonal relative MRI values and MRI capacity by resource type, he said.

ISO-NE previously presented initial impact analysis results associated with its resource capacity accreditation project, which the RTO incorporated into the broader CAR project in 2024. These results indicated significant capacity revenue boosts for imports, energy efficiency, non-intermittent hydropower, dual-fuel generators and nuclear plants, along with revenue declines for energy storage, oil-only resources, hybrid resources and active demand response. (See ISO-NE: RCA Changes to Increase Capacity Market Revenues by 11%.)

Building on the base case modeling, ISO-NE plans to run sensitivity analyses based on stakeholder recommendations. Potential sensitivities could alter factors related to heating and transportation electrification, behind-the-meter generation, renewable and storage development, and retirements of oil-fired generators.

Because ISO-NE’s proposed MRI accreditation approach is intended to compensate resources for their reliability contributions during the hours with greatest shortfall risk, changes to the load profile or resource mix could significantly affect resource accreditation by shifting when these hours occur.

One stakeholder expressed concern that the 2025 CELT report does not include large loads expected to come online and urged the RTO to consider running a sensitivity analysis that considers the effects of this potential demand. ISO-NE indicated this may be challenging due to the lack of “well-established evaluation frameworks.”

ISO-NE plans to give a follow-up presentation on the impact analysis in February and has requested stakeholder feedback on its proposed approach.

Gas Capacity Demand Curve

Also at the Markets Committee meeting, ISO-NE continued discussion on its proposal for a new gas capacity demand curve intended to account for generators’ limited access to pipeline gas during cold-weather periods. (See ISO-NE Talks CAR Gas Constraints, Seasonal Risk Split, Impact Analysis.)

The current rules, which do not account for the region’s gas constraint, create a “money for nothing problem” by fully accrediting gas-only resources that may not be able to run when pipeline access is limited, said Stephen Otto, manager of economic analysis at ISO-NE.

While ISO-NE initially proposed to account for gas constraints within the accreditation process, it has shifted its approach due to concerns about how gas would be allocated to different resources. Under the current accreditation proposal, the RTO would model gas-only resources without fuel limits.

“When gas availability is constrained, the inclusion of the gas capacity demand curve in the winter capacity market would affect the quantity of gas capacity procured and its settlement price in the same way that an export-constrained capacity zone demand curve affects the procurement and settlement price of export-constrained capacity zone capacity,” the RTO noted in a Jan. 7 memo.

Otto said the changes are essential for sending accurate market signals, procuring the most cost-effective mix of capacity, and preventing reliability issues associated with relying on gas capacity that is unable to perform during cold weather. The proposal likely would provide an incentive for gas resources to enter firm fuel arrangements that would exempt the resources from the gas capacity demand curve.

Intermittent Resource Accreditation

ISO-NE also discussed its proposed approach to accrediting intermittent resources. It plans to use hourly profiles for all intermittent resources; it would construct hourly wind and solar profiles based on resource characteristics and historical weather patterns; and it would construct profiles for run-of-river hydropower, landfill gas, municipal solid waste, wood and biogas generation based on historical output data.

The RTO plans to model all non-settlement-only intermittent resources on an individual basis and model settlement-only intermittent resources on an aggregated basis, “grouped by load zone and IPR type,” said Hannah Johlas of ISO-NE. This aggregation would apply only to solar and intermittent hydro resources, and the RTO would not rely on aggregates for groups made up of fewer than 10 resources, Johlas added.

ISO-NE plans to continue discussions on intermittent resource modeling and accreditation at the Markets Committee meeting in February.

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FERC Staff Recommends Relicensing of Idaho Power’s Hells Canyon Dams

FERC staff said the commission should relicense three Idaho Power-owned hydroelectric dams that have been operating under annual licenses since 2005, finding the company’s proposed measures, along with staff recommendations, adequately mitigate the environmental impact of the dams.

Commission staff on Jan. 14 issued a draft supplemental environmental impact statement (SEIS) after Idaho Power filed proposed modifications for the 1,222.3-MW Brownlee, Oxbow and Hells Canyon dams, collectively the Hells Canyon Project.

The dams are located along the Snake River in Idaho and Oregon, and occupy about 5,270 acres of federal land, according to the draft SEIS.

“We are pleased to have reached this milestone in the relicensing process for the Hells Canyon Complex, which is an essential part of Idaho Power’s resource portfolio,” Idaho Power spokesman Brad Bowlin told RTO Insider.

The company will provide detailed answers to FERC by March 2, which is the deadline to submit public comment on the draft SEIS.

Idaho Power applied for a new license in 2003 to operate the Hells Canyon Project. The company has operated the dams under annual licenses since the current one expired in 2005, the SEIS states.

FERC issued the final environmental impact statement for Hells Canyon in 2007, but following several new developments, including settlements with key stakeholders, FERC prepared a supplemental environmental review to account for these changes.

Among the recent developments is a 2019 settlement between the company and Oregon and Idaho that resolved disputes over water quality and protections of Chinook salmon and steelhead. Following the settlement, Oregon and Idaho issued 401 certifications for Hells Canyon under the Clean Water Act.

In 2020, Idaho Power filed a supplement to its license application that included new environmental measures proposed under the 2019 settlement.

In 2022, FERC issued a notice of intent to prepare a final SEIS to address the new measures. Following the notice, Idaho Power filed a settlement agreement with the U.S. Forest Service in 2024 related to the company’s use of federal land.

Hells Canyon Dam | Idaho Power

In the Jan. 14 draft SEIS, FERC staff wrote the main concerns with relicensing are the effects on sediment supply and transport, water quantity and quality, aquatic resources, terrestrial and cultural resources, and the adequacy of recreational facilities to meet expected demand over the term of any new license.

FERC staff recommended relicensing the project under most of Idaho Power’s proposed measures and “certain mandatory conditions and recommendations made by state and federal agencies and some staff-recommended modifications to further minimize project-related effects on aquatic and terrestrial resources, threatened and endangered species, recreation resources, and cultural resources,” a news release stated.

The approach recommended by staff includes all conditions in the 401 certifications issued by Oregon and Idaho except for three: implementation of three phosphorus load-reduction programs, implementation of a program that consists of completing habitat restoration projects in the Snake River Basin upstream of the project and implementation of a mercury and methylmercury study.

“Because there is no project nexus associated with these conditions, staff concluded that there would be no project-related benefit to implementing these measures and does not include them in the staff alternative,” the draft SEIS states.

The draft SEIS estimates power generated by Hells Canyon under the staff-recommended approach could “cost $120,748,800, or $21.67/MWh, less than the likely alternative cost of power.”

“We chose the staff alternative as the preferred alternative because: (1) the project would continue to provide a dependable source of electrical energy for the region (5,571,005 MWh annually); (2) the public benefits of the staff alternative would exceed those of the no-action alternative; and (3) the proposed and recommended environmental measures would protect and enhance environmental resources affected by the project,” the draft SEIS states. “The overall benefits of the staff alternative would be worth the cost of the proposed and recommended environmental measures.”

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BPA Prepares Pilot Program to Reduce Balancing Reserves

The Bonneville Power Administration is starting a new pilot program to decrease the balancing reserve capacity it must hold to account for variable resources by connecting new types of generation facilities to its grid.

As part of the New Generation Technology Pilot, BPA will work with generators to “encourage development of technologies and operations” that reduce balancing reserve capacity requirements in the agency’s balancing authority area, BPA staff said at a Jan. 13 workshop to explain the program.

A presentation from the workshop outlined three objectives for the pilot:

    • incentivizing “accurate scheduling and performance”;
    • establishing a “technology inclusive policy” for participation; and
    • fostering collaboration between BPA and generators “to enable novel approaches to lower the amount of capacity needed” to integrate variable generation.

Participating resources could include nuclear power plants or wave energy structures, BPA electric engineer Ross Ponder said during the workshop.

A proposed project will need to meet performance metrics, which will be established based on historical balancing reserve capacity usage and projections, Ponder said. Participation in the pilot will rely on a reduction in station control error (SCE), and BPA will revise a project’s performance expectations if the project increases its SCE, Ponder said.

The pilot program “essentially can be … used to provide a method to reduce generators’ balancing reserves capacity,” Ponder said.

Battery energy storage systems (BESS) and nuclear facilities are two possible resource types eligible for the pilot, Bart McManus, a BPA engineer, said at the workshop.

However, “we are not saying [a project] has to be BESS or nuke,” McManus added. “We are looking for innovative strategies. We don’t run solar plants. We don’t run nuke plants. So if you have something that could work, absolutely bring it to the table and we will talk through it.”

One meeting participant asked about the current performance and buildout of co-located generation and battery storage in BPA’s region.

“We don’t really have a lot of examples of co-located generation,” BPA engineer Nancy Morales said. “So the status quo is there is minimal impact of co-located resources.”

A meeting participant also said that the pilot has “technically been around for a while, but the last I heard about it … is that nobody had taken Bonneville up on the offer to participate in it.”

“When did this pilot begin and has anyone taken you up on it yet?” the participant added. “Is there anything that is different about it now?”

“We have a few requests to join the [pilot],” Ponder said. “We are currently in the design phase … but we don’t have anyone active yet.”

Ponder added that he expected to hold a few more meetings later in 2026 to discuss the pilot and respond to future questions.

When a generator or load connects to BPA’s grid, BPA must provide balancing reserves at a rate and amount determined by the agency for reliability purposes. BPA can provide balancing reserve capacity to cover a 99.7% planning standard for balancing error events without unreasonably impairing reliability, the agency said in a September 2025 document.

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IESO Reliability Compliance Plan Focuses on CIP, Modeling, IBRs

IESO is targeting six areas of NERC’s reliability standards in its 2026 compliance program, largely continuing a focus on issues it has prioritized since 2023.

The 2026 Market Assessment and Compliance Division (MACD) Reliability Standards Compliance Monitoring Plan will prioritize:

    • Critical Infrastructure Protection (CIP)
    • Inadequate Models Impacting Planning and Operations (MOD/PRC)
    • Gaps in Program Execution (FAC)
    • Automatic Underfrequency Load Shedding (PRC)
    • Inverter-Based Resources (PRC), and
    • Extreme Weather Response (EOP)

MACD says its priorities consider the reliability standards’ applicability to Ontario; the assessed reliability risks and compliance history of each standard; power system infrastructure and demand changes; and emerging threats and vulnerabilities.

“While market participants are required to comply with and be able to demonstrate compliance with all applicable reliability standards at all times, MACD puts a more significant focus on a subset of these market rules and reliability standards that are more explicitly monitored for compliance in a given year,” IESO said.

The MACD conducts scheduled and unscheduled audits, in addition to accepting self-reports and self-certifications.

NERC’s 2025 reliability indicators | NERC

MACD selects the subject of scheduled audits based on “both market participant specific information and Ontario-specific risks.” Subjects are provided at least 90 days’ notice before the start of scheduled audits. MACD also may conduct unscheduled audits “potentially with very little or no notice,” it said.

NERC Concerns

In its 2025 State of Reliability Report, NERC said key performance metrics such as frequency response and misoperation rates continued to improve or remain stable.

It said weather continued to be responsible for the most severe outages in 2024, citing two significant winter storms and five major hurricanes. It noted an improvement in winter performance, with no operator-initiated load sheds, in part due to efforts to improve generator performance during extreme cold.

The report says large data centers pose a “significant near-term reliability challenge” because they are growing faster than generation and transmission infrastructure. It said more accurate models of data centers’ operational characteristics are needed because of their “voltage sensitivity and rapidly changing, often unpredictable, power usage.”

NERC also noted improvements in frequency response in regions with high concentrations of battery energy storage systems, but said some inverter-based resources “continue to unexpectedly reduce output following disturbances that generators have historically been expected to ride through.”

MACD Findings

MACD’s Sanctions and Negotiated Settlements notices include violations of market rules, as well as several cases involving NERC and Northeast Power Coordinating Council reliability standards.

In 2022, IESO reached a $1.67 million settlement with Ontario Power Generation and a $1 million agreement with Hydro One Networks for failing to properly plan a maintenance outage at the Darlington Nuclear Generating Station. IESO alleged that OPG and Hydro One failed to recognize the purpose and limits of electrical protective relay schemes. In one instance, equipment at the Bowmanville Switching Station operated without this scheme for approximately five months without incident, which IESO concluded “gave rise to a significant market and electrical reliability concern with a low probability of occurrence.”

In 2023, it reached a $327,000 settlement with Kirkland Lake Power Corp. and a $12,500 agreement with Iroquois Falls Power Corp. IESO said Kirkland Lake failed to maintain evidence that it maintained its equipment as required and, in another event, incorrectly adjusted the underfrequency trip settings on certain electromechanical relays. Iroquois Falls lacked evidence that it conducted the required annual vegetation inspection of a transmission line in 2018.

GenSet Resource Management agreed in 2023 to pay $500,000 for its failure to comply with dispatch instructions for operating reserves between 2013 and 2019, which IESO said posed a reliability risk.